Dry mix for water based drilling fluid

ABSTRACT

A drilling fluid or mud having several components, including leonardite (humic acid); potassium acetate; partially hydrolyzed polyacrylamide (PHPA); polyanionic cellulose polymer (PAC); sulfonated asphalt; sulfoalkylated tannin; polystyrene maleic anhydride copolymer; micronized cellulose fiber; calcium carbonate; and calcium carbonate. These components are preferably premixed in a dry formulation as a powder or as pellets, and shipped to the site in bags or bulk barrels. This offers substantial advantages over the prior art in that the drilling mud of the present invention may be formed simply by adding the dry mix to a predetermined amount of water, and is thus much easier to make than the prior art wet mix drilling fluids, which typically require precise ratios of several different powders and liquids to be mixed together. The humic acid serves as hydration buffer to help keep the powder or pellets dry and flowable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The prior art relates to petroleum wells in general and to drillingfluids in particular.

2. Prior Art

Drilling muds or drilling fluids are used in drilling operations such asin the drilling of petroleum wells. The drilling apparatus comprises inthe most general terms, a length of drill stem (the drill string) oftenhaving a rotary drill at its downhole end. Drilling fluid or “mud” ispumped through the well bore.

Every drilling mud is comprised of a base fluid and some combination ofdry and or liquid components that are mixed into the base fluid tocreate a mud that has the desired components in the desired ratios.Typically, such mixing is done in the field, and involves the labor ofmany people and numerous bags, tanks, pails, mixing hoppers, mixingpumps, and hoses.

There are two main types of drilling mud: oil based muds (OBM) and waterbased muds (WBM). As their names imply, the two types of muds can bedifferentiated by the nature of their base fluids. Fresh or salt watermakes up the base fluid in WBM's while diesel oil, mineral oils, orsynthetic oils often serve as the base fluid for OBM's, although saltwater is often emulsified into the base fluid with primary and secondaryemulsifiers in OBM's.

The drilling mud must accomplish several tasks. One of the primarypurposes of the drilling mud is lubrication. The drilling mud lubricatesthe drill bit, helping to prevent damage to the bit as it grinds throughthe earth. The drilling mud also lubricates the drill stem, preventingit from sticking to the walls of the well bore as it is rotated.Additionally, the drilling mud cools the bit and string, dissipating theheat generated by the drilling itself and the geothermal heat, wherepresent.

As the drill bit rotates, it dislodges pieces of rock, clay, dirt, andetc, known as cuttings. Additionally, portions of the well bore may caveoff from time to time. While such cavings are to be avoided, ifpossible, both the cavings and the cuttings must be removed. This isanother function of the drilling fluid. As drilling mud is pumpedthrough the well bore it picks up and carries these drill cuttings andcavings out of the well bore. Additionally, the drilling mud should becapable of suspending the cuttings in the drilling mud when circulationis stopped. If the drilling mud does not have enough gel strength tokeep the cuttings in suspension, they will settle out of the drillingmud.

If the cuttings settle out of the drilling mud, they can collect incutting beds—piles of cuttings and cavings that have collected at onepoint in the well bore. However, in directional drilling, the well borecan have one or more sections that are between horizontal and vertical.The low sides of these sections of the well bore are particularlysusceptible to the formation of cutting beds, particularly in bendswhere the bore moves from a more vertical section to a more horizontalsection. Cutting beds in these positions can bind the drill stem. Thiscan impede rotation of the stem and impede steerage of the bit indirectional drilling. Cutting beds can also impede the insertion ofadditional drill stem or the removal of drill stem that is already inplace. Similarly, cutting beds can cause the bit or other downhole toolsto become stuck as well. Thus, it is important for a drilling mud tominimize the rate at which cuttings fall out of suspension when thecirculation of the drilling mud stops.

Another requirement of the drilling mud is to help hold up the well borewalls. The drill bit necessarily cuts a hole in the earth that isslightly larger than the diameter of the drill stem. The drilling mudcirculating in the well bore provides support to the well bore walls andprevents them from collapsing.

Instability in the well bore is an especially frequent problem in shaleformations. Shales are complex clay rich geological sediments. Theirnotorious instability is believed to arise from the fact that some ofthe minerals responsible for cementing the shale components together areat least partially soluble in water. Adding water to these componentswill cause them to swell and dissolve, thereby reducing the forcesholding the shale together and resulting in its deterioration.Conversely, drying the shale will increase the cementing effect theminerals have on the shale, causing the shale to harden and strengthen.The instability of a shale will vary directly in proportion to theamount of time spent in open hole operation—that is, the amount of timewith no casing separating the drilling mud in the well bore from theformation.

One clay mineral that is especially problematic is sodiummontmorillonite, also known as swelling bentonite. Sodiummontmorillonite is especially problematic because it expands to severaltimes its original volume when it encounters water. Thus, the water in aWBM pumped through shale formation can cause the sodium montmorillonitein the well bore wall to swell substantially. Such swelling can weakenthe bond between the clay particles and the other components of theshale. This can cause the well bore wall to slough off or to collapsealtogether. Additionally, the swelling of the clay particles can causethe well bore diameter to shrink, such that it may restrict the drillstring or actually cause the drill string or any number of downholetools to become stuck. Also, when the clay particles enter the drillingmud and swell, they can increase the drilling mud viscosity beyonddesirable levels, which can increase the well bore pressure, making themud more difficult to pump and simultaneously increasing stress on thewell bore, leading to increased risk of well bore erosion or collapseand/or loss of drilling fluid to the surrounding formation through thewell bore walls. Shales high in sodium montmorillonite, and thusespecially susceptible to the foregoing problems, are commonlyencountered in the Gulf of Mexico and the North Sea.

When well bores are expected to encounter shale formations, drillerswill often use an OBM to reduce the exposure of the shale to water.However, the cost of using an OBM is significantly greater than WBM'sbecause of the cost of the base fluid. Additionally, OBM's and theircuttings are subject to more rigorous environmental treatment than theirWBM counterparts.

Another function of the drilling mud is counteracting the pressure ofthe formation. When petroleum reservoirs are encountered duringdrilling, they may be under significant pressure. These pressures willtend to assault the bore wall, potentially causing it to implode andalso potentially forcing the petroleum product into the well bore. Oneway of addressing the problem is by increasing the density of thedrilling mud. This will counter the pressurized formations encountereddownhole, neutralize the pressure on the well bore wall, and prevent thepetroleum products from escaping into the well bore.

The well bore may pass through many different types of soil, rock, shaleand sand. Although some of these formations will be pressurized asdiscussed above, others will not be pressurized or will be under lesspressure than the drilling mud. In such cases, a common and expensiveproblem is the loss of drilling mud to the formation. Althoughproblematic in WBM's and OBM's these types of losses are particularlytroublesome in OBM's. However, with either mud type, the mud is lost inthe same manner. Fractures or porous soil materials essentially act likeleaks in the well bore, allowing the drilling mud to simply flow out ofthe bore. It is important to minimize such losses. To this end, thedrilling mud is configured to deposit a thin filter cake on the walls ofthe well bore.

The filter cake is a thin layer of non-water permeable or semi-permeablematerial at the wall of the well bore. It seals fractures in theformation that open into the well bore and otherwise acts as a barrierbetween the well bore and the formation through which the well borepasses. To the extent that the formation is porous or otherwise capableof receiving fluids under pressure, the drilling fluid will run out ofthe well bore into the surrounding formation. However, as the drillingfluid runs out of the well bore, items that are not in solution will becarried with the drilling fluid to the well bore wall. Those items thatare too large to pass through the pores of the formation will clog thepores and become caked to the well bore wall, forming the filter cake,which will inhibit further fluid flow out of the well bore. The waterphase of the drilling fluid that is squeezed through the filter cake iscalled mud filtrate. The object of the filter cake is to minimize theamount of mud filtrate that escapes from the well bore.

Another problem that arises in low pressure formation is differentialsticking. This occurs when the pressure of the drilling mud exceeds thepressure of the surrounding formation, and the resultant difference inpressure forces the drill stem against the well bore wall. The pressureexerted against the drill stem by the drilling mud can be sufficient tobind the drill stem, causing it to become stuck. The drilling mud shouldbe configured to prevent or inhibit flow into such low pressure sands inorder to prevent differential sticking as well as the accompanying mudloss.

The drill string is typically composed of dozens if not hundreds ofsections of approximately thirty-one foot sections of steel pipe. Theweight of such a length of pipe is significant. Another of the manypurposes of the drilling mud is to help to support this weight, throughits buoyancy.

Although there are many known drilling mud compositions that can achieveone or more of the foregoing requirements, obtaining such a drilling mudin the field can be difficult. Many drilling fluids additives must betransported in liquid form because of the hydroscopic nature of theiringredients. This takes up significant shipping space and makes handlingthe additives more difficult. Additionally, as mud engineers attempt tooptimize a drilling mud to match the particular conditions encounteredon site, they may consume a disproportionate amount of a particular mudcomponent. Because of the remote locations where petroleum explorationis frequently conducted, shipping space is often at a premium. Thus,using an excess amount of a single component in an effort to matchencountered conditions may cause the mud engineer to run short of thatparticular component. This can lead to expensive downtime whileadditional supplies of the component are sought. Therefore, a drillingfluid that meets the following objectives is desired.

OBJECTS OF THE INVENTION

It is an object of the invention to provide a drilling fluid that iscapable of lubricating the drilling bit.

It is another object of the invention to provide a drilling fluid thatis capable of coating, lubricating, and inhibiting the hydration of wellbore cuttings.

It is another object of the invention to prevent the drill bit andstabilizers from balling up with up with clay or shale.

It is another object of the invention to provide a drilling fluidcapable of carrying drill cuttings out of the well bore.

It is another object of the invention to provide a drilling fluidconfigured to reduce cutting bed build up during the drilling ofdeviated wells.

It is still another object of the invention to provide a drilling fluidcapable of supporting the well bore walls.

It is still another object of the invention to provide a drilling fluidconfigured to minimize well bore erosion.

It is yet another object of the invention to provide a drilling fluidcapable of substantially sealing the well bore.

It is still another object of the invention to provide a drilling fluidcapable of substantially inhibiting the hydration of shale formations.

It is still another object of the invention to provide a drilling fluidcapable of forming a thin, tough, lubricated filter cake on the wellbore wall.

It is still another object of the invention to provide a drilling fluidconfigured to inhibit differential sticking of the drill string and ofwire-line tools.

It is yet another object of the invention to provide a drilling fluidcapable of being used to hydraulically drive a mud motor.

It is a still further object of the invention to provide a drillingfluid that may be easily transported to remote locations.

It is still another object of the invention to provide a drilling fluidthat may be easily prepared on site.

It is yet another object of the invention to provide a drilling fluidwhose components may be stored in a dry powder.

It is still another object of the invention to provide a drilling fluidwhose components may be easily pelletized.

SUMMARY OF THE INVENTION

The invention comprises a drilling fluid or mud having severalcomponents, including leonardite (humic acid); potassium acetate;partially hydrolyzed polyacrylamide (PHPA); low viscosity polyanioniccellulose polymer (PAC); sulfonated asphalt; sulfoalkylated tannin;polyacrylate copolymer and/or maleic anhydride copolymer; micronizedcellulose fiber; calcium carbonate; slaked lime; potassium carbonate;bentonite; and xanthan gum. These components are preferably premixed ina dry formulation, and shipped to the site in bags or bulk tanks. In onepreferred embodiment, the leonardite, potassium acetate, PHPA, PAC andsulfonated asphalt may be mixed as one composite additive and theremaining ingredients mixed as a second additive.

This offers substantial advantages over the prior art in that thedrilling mud of the present invention may be formed simply by adding apredetermined amount of the dry mix to water, and is thus much easier tomake than the prior art wet mix drilling fluids. Mixing liquidcomponents also typically requires multiple tanks, hoses, stands andconnections, and close supervision during mixing. Moreover, spillsfrequently occur in mixing these prior art mud components. Thecomponents of many prior art liquid additives include oil basedcarriers. As a result, when they are spilled, a dangerous slip and fallcondition is often created. No such condition is created by a spill ofthe dry components of the present invention.

Furthermore, because of the remoteness of many drilling sites, shippingcan be a problem. Transporting the drilling fluid additives to thedrilling site in a dry form will take up much less space both in transitand during storage on site, allowing the ingredients for a large amountof fluid to be brought in at once and stored on site through theduration of the project.

The foregoing advantages complement each other. As stated above, whenliquid additives are used, on site personnel will make up the drillingfluid by combining preset ratios of several components, typically inlarge quantities using several tanks, hoses, and etc. Given thedifficult conditions under which many wells are drilled, errorsfrequently arise in the mixing process, often resulting in excessquantifies of one or more components being spilled or added to thedrilling mud mixture. This can lead to a premature consumption of one ormore key ingredients and to the well site being effectively out ofdrilling fluid because one drilling fluid component has run out. Becausethe drilling operation cannot run without drilling fluid, drilling willeffectively be stopped while more of the missing component is soughtwhich, given the remoteness of some drill sites, can take a significantamount of time. Such delays can constitute a substantial expense, asmany drilling rigs cost anywhere from several thousand to severalhundred thousand dollars (U.S.) per day. Thus, having a dry mix drillingmud in which all or substantially all of the components are premixed andwhich can be prepared merely by adding a dry powder to water, willeliminate the possibility that the drilling mud will run out simplybecause one component has been prematurely consumed.

Additionally, the ability to transport the drilling mud in a dry formwill make it easier to carry excess drilling fluid mix to a well site atthe commencement of drilling, and thus to insure against running out ofdrilling fluid by keeping excess stock on hand. The volume of theindividual liquid components, the limited shipping space, and thelimited storage on many well sites made shipping excess drilling fluidto a site difficult with many prior art wet mix drilling fluids. Thepresent invention will make it much easier to keep sufficient inventoryon hand in order to guard against premature consumption of the drillingfluid.

The use of dry mix drilling fluid additives is complicated by the factthat several common drilling mud components, particularly PHPA andpotassium acetate, are quite hydroscopic. When these components areincluded in a powder, the powder absorbs water from the atmosphere andforms clumps, solid blocks, or particularly in the case of potassiumacetate and PHPA, soupy semi-liquids, after only a short exposure to theatmosphere. While such hydration can be avoided through careful storagepractices, the conditions at most drilling sites makes this at leastimpractical, if not impossible. Consequently, many prior art drillingfluid additives have been provided in liquid form. By adding a hydrationbuffer to the mixture disclosed herein, the inventor has discovered thathe can maintain the mixture in a flowable powder form, allowing him toachieve all of the advantages of a dry mix drilling fluid.

DETAILED DESCRIPTION OF THE INVENTION

The invention is a water based drilling fluid or drilling mud havingseveral components. The first is a shale stabilizer. This componentinhibits the absorption of water by the shale. Shale is made of severaldifferent types of material. When the clay components such as sodiummontmorillonite absorb water, they swell. Swelling by one shalecomponent but not the others weakens the entire shale structure and cancause large pieces of the shale to cave into the well bore. Thus, bypreventing clay components from absorbing water, the entire shaleformation is stabilized.

Also, as the drill bit passes through a shale formation, it willdischarge shale cuttings into the well bore. If these cuttings absorbtoo much water in the drilling mud, the drilling mud will thicken whichcan result in an unintentional and excessive increase in the circulatingmud pressure. The shale stabilizer in the drilling mud inhibits theabsorption of water by the shale cuttings as well as the shale formationat the well bore walls.

The shale stabilizers are very hydrophillic. The inventor's preferredshale stabilizers are potassium acetate and a low molecular weight (1 to8 million and preferably between 6 and 8 million) partially hydrolyzedpolyacrylate-polyacrylamide copolymer (PHPA). Suitable PHPA can beobtained from Ciba Specialty Chemicals Corp. of Suffolk, Va.

The PHPA copolymer has numerous polar functional groups. These polarfunctional groups are believed to allow the PHPA to form a coating overthe shale in the well bore wall as well as to encapsulate the shaleparticles in the mud stream. This PHPA coating or encapsulation, as thecase may be, has several effects. First, it prevents further hydrationof the shale formation or cuttings by direct contact with the drillingmud. Second, it seals the fractures and pores in the surface of theshale formation and cuttings, closing the shale to capillary movementthat would allow mud filtrate into the formation. When the PHPA coatsthe shale cuttings in the mud, it lubricates them and prevents them fromsticking to one another. This prevents the cuttings from collecting or“balling” on the bit or the stabilizers. Preventing the cuttings fromsticking to drill string components lessens the chances that thecomponents will become stuck in the well bore and simultaneously makesit more likely that the cuttings themselves will be circulated out ofthe well bore with the mud so they can be removed at the surface. ThePHPA coating also inhibits the dispersion of the shale cuttings bypreventing them from breaking into small pieces which are oftendifficult if not impossible to remove from the mud. Also, by lubricatingthe cuttings, the PHPA helps to prevent them from scouring the well borewall as the mud flows through the bore.

In the preferred embodiment, the PHPA is provided in the drilling mud inconcentrations between about 0.71 grams per liter and about 5.71 gramsper liter and more preferably in concentrations between about 1.4 andabout 2.8 grams per liter. As discussed in more detail below, thepreferred embodiment of the invention is a dry drilling mud additive,which is mixed into water to make the drilling mud. To achieve thedesired concentration, between about 0.25 and about 2.0 pounds of PHPAand preferably between about 0.5 and about 1.0 pounds of PHPA should beadded per barrel (42 gallons) of water.

The preferred embodiment of the present invention also includes a secondshale stabilizer in the form of an alkali metal acetate, preferablypotassium acetate (KC₂H₃O₂). Suitable potassium acetate can be obtainedfrom Jarchem Industries, Inc. of Newark, N.J. The potassium ion is agood shale stabilizer. Its size is believed to allow it to fill theinterstitial spaces in the clay platelet, tetrahedral sheets that makeup the clay, and thereby physically block capillary hydration of theshale. Additionally, when potassium acetate is dissolved in the waterbased mud, potassium and acetate ions are released. The increasedconcentration of solute in the mud is believed to reduce the osmoticpressure of the mud across the filter cake, thereby reducing the osmoticflow of mud filtrate from the mud to the formation. Also, potassium ionsare believed to be able to displace sodium ions in the shale, making theshale more stable.

In the preferred embodiment, the potassium acetate is provided in thedrilling mud in concentrations of between about 2.9 grams per liter andabout 14.3 grams per liter and more preferably in concentrations betweenabout 5.7 and about 11.4 grams per liter. As discussed in more detailbelow, the preferred embodiment of the invention is a dry drilling mudadditive, which is mixed into water to make the drilling mud. To achievethe desired concentration, between about 1 and about 5 pounds ofpotassium acetate and preferably between about 2 and about 4 pounds ofpotassium acetate should be added per barrel (42 gallons) of water.

Shale stabilizers such as PHPA and potassium acetate are hydroscopic. Asa result, they typically do not form very stable powders. In fact,powders of potassium acetate and/or PHPA typically absorb water from theatmosphere very rapidly. As a result, such powders left open willquickly develop lumps, large blocks, or semi-liquid globs, depending onthe humidity and the length of time they are exposed to the atmosphere.Thus, storing shale stabilizers in a flowable powder form is difficultunder ideal conditions, and nearly impossible under the conditions thatpetroleum exploration is often conducted, such as the high humidityencountered on offshore drilling platforms. For this reason, shalestabilizers, and drilling mud components in general are typicallystored, transported, and mixed in solution.

The inventor has discovered that the addition of hydration buffers, suchas humic acid, a principle component of leonardite (also known aslignite), can prevent the hydroscopic drilling fluid components fromcaking or clumping, keeping the entire mix a dry flowable powder. Humicacid is known to block electrostatic interaction. This is believed toinhibit the wetting of the other mixture components. Suitable leonarditecan be obtained from Black Hills Bentonite, Inc. of Mills, Wyo.

The buffers are believed to inhibit clumping partly by preventing shaleinhibitors from absorbing water from the atmosphere, as discussed above,and partly by simply being homogeneously mixed with the shale inhibitorsand other hydrophilic particles in sufficient quantity to prevent thoseparticles that have absorbed water from the atmosphere from being ableto physically combine with one another to any significant degree.

In addition to serving to keep the mixture components from clumping, thebuffers also have a functional effect in the drilling mud, once water isadded. Humic acid is known to make clays unwettable. Thus, the humicacid in leonardite and other buffers will help prevent the mud filtratefrom being absorbed by the clays in the shale encountered in the wellbore. This will protect the shale and reduce the loss of mud filtrate.

Humic acid also improves the compressibility and lessens thepermeability of the filter cake. Humic acid also improves the ability ofthe mud to remain fluid at high temperatures—above about 250° F. Theoperational advantages that the mud derives from humic acid at hightemperatures primarily comes from the fact that humic acid does notbreak down at elevated temperatures as readily as some other drillingmud components, and thus the humic acid continues to perform the abovedescribed functions at higher temperatures while some other mudcomponents may not.

In the preferred embodiment, leonardite is provided in the drilling mudin concentrations between about 5.7 grams per liter and about 42.9 gramsper liter and more preferably in concentrations between about 22.9 andabout 37.1 grams per liter. As discussed in more detail below, thepreferred embodiment of the invention is a dry drilling mud additive,which is mixed into water to make the drilling mud. To achieve thedesired concentration, between about 2 and about 15 pounds of leonarditeand preferably between about 8 and about 13 pounds of leonardite shouldbe added per barrel (42 gallons) of water.

It should be noted that although the foregoing concentrations are givenin terms of leonardite, the principle active ingredient in theleonardite is believed to be humic acid, which is believed to make upabout 85 percent by weight of the leonardite. Thus, for example, 5.7grams of leonardite would contain about 4.8 grams of humic acid.Similarly, 15 pounds of leonardite would contain about 12.8 pounds ofhumic acid.

The preferred embodiment of the drilling mud also includes a cellulosepolymer, such as a low viscosity polyanionic cellulose polymer (PAC),available from Drilling Specialties, Co., LLC of Bartlesville, Okla., orcarboxymethylcellulose (CMC), available from Aqualon Oilfield Chemicals,a division of Hercules, Inc., of Houston, Tex. The cellulose polymerwill provide reduced mud filtrate loss by forming part of the filtercake. The cellulose polymer will also help to coat and lubricate shaleformations and shale cuttings in the mud.

In the preferred embodiment, cellulose polymer in the form of PAC isprovided in the drilling mud in concentrations between about 0.71 gramsper liter and about 11.4 grams per liter and more preferably inconcentrations of between about 2.9 and about 5.7 grams per liter. Asdiscussed in more detail below, the preferred embodiment of theinvention is a dry drilling mud additive, which is mixed into water tomake the drilling mud. To achieve the desired concentration, betweenabout 0.25 and about 4 pounds of cellulose polymer and preferablybetween about 1 and about 2 pounds of cellulose polymer should be addedper barrel (42 gallons) of water.

The preferred embodiment of the drilling fluid also contains dryparticulate sulfonated asphalt, available from Drilling Specialties Co.,LLC of Bartlesville, Okla. The principle function of the asphalt is tostabilize shale formations by acting as a sealant, mechanically pluggingand sealing the small fissures and pores in the formations lining thewell bore and within the filter cake. In addition to forming part of thefilter cake, the asphalt will increase lubricity of the mud, reducefriction, and coat cuttings in the mud. Although asphalt is preferred,there are several other known components that may be used in place ofthis ingredient including gilsonite (uintaite), carbon black, andgraphite.

In the preferred embodiment, sulfonated asphalt is provided in thedrilling mud in concentrations between about 5.7 grams per liter andabout 28.6 grams per liter and more preferably in concentrations ofbetween about 11.4 and about 22.9 grams per liter. As discussed in moredetail below, the preferred embodiment of the invention is a drydrilling mud additive, which is mixed into water to make the drillingmud. To achieve the desired concentration, between about 2.0 and about10.0 pounds of sulfonated asphalt and preferably between about 4.0 andabout 8.0 pounds of sulfonated asphalt should be added per barrel (42gallons) of water.

As the solids content of the mud and the temperature at the bottom ofthe well bore increase, the mud's yield point—i.e. the stress, measuredin pounds force (lbf) per 100 square feet, required to maintain fluidmovement—can become excessive. If the yield point is too high, thepressure exerted by the fluid will exceed the formation fracturegradient—the pressure at which the mud will cause the well bore wall torupture. Suitable yield points range from about five to about twentypounds of force per hundred square feet and preferably range from abouteight to about twelve pounds of force per hundred square feet. To helpkeep the yield point in the desired range, a thinning rheology modifiermay be included in the preferred embodiment.

A preferred thinning rheology modifier is sulfoalkylated tannin powder,which may be obtained from the Drilling Specialties Company ofBartlesville, Okla. Other suitable thinning rheology modifiers includelignosulfonate, copolymers of acrylic acid and polyacrylic acid,polystyrene maleic anhydride copolymer, and AMPS(2-acrylomido-2-methylpropane sulfonic acid) polymer. Humic acid alsoacts as a rheology modifier.

Where a large amount of clay is expected to be encountered duringdrilling, the mud's viscosity can be expected to increase as its claycontent rises. In such circumstances, it may also be desirable reducethe mud's viscosity. A thinning rheology modifier may be employed forthis purpose as well.

In addition to controlling yield point and viscosity, the rheologymodifiers can also help regulate the mud's gel strength, i.e. the timeit takes a fluid to begin acting like a gel when it becomes static. Theability of the mud to act like a gel is important because it is thischaracteristic that allows the mud to keep the mud solids in suspensionwhen circulation is stopped. Increasing the mud gel strength will helpthe mud keep cuttings suspended, which in turn will help the mud carrythe cuttings to the surface where they can be removed from the mudstream. The desired gel strength of the mud is preferably between aboutthree and about twelve pounds of force per hundred square feet, and morepreferably between about four and about six pounds of force per hundredsquare feet, as measured when the mud has been at rest for ten minutes.

It is desirable that the drilling mud be thixotropic, meaning that themud should thin upon shearing but form a gel when at rest—preferably arelatively fragile gel. Gelation is needed so that the cuttings will notimmediately fall out of suspension when the mud stops being pumpedthrough the well bore. However, a relatively low gel strength is neededso that pumping may be recommenced without requiring pressures thatwould exceed the well bore fixture gradient. Thus, thinning rheologymodifiers and gelling rheology modifiers are both included in thepreferred embodiment.

In the preferred embodiment a sulfoalkylated tannin thinning rheologymodifier is provided in the drilling mud in concentrations between about1.4 grams per liter and about 14.3 grams per liter and more preferablyin concentrations of between about 2.9 and about 11.4 grams per liter.As discussed in more detail below, the preferred embodiment of theinvention is a dry drilling mud additive, which is mixed into water tomake the drilling mud. To achieve the desired concentration, betweenabout 0.5 and about 5.0 pounds of sulfoalkylated tannin rheologymodifier and preferably between about 1.0 and about 4.0 pounds ofsulfoalkylated tannin rheology modifier should be added per barrel (42gallons) of water.

An additional thinning rheology modifier may be included in thepreferred embodiment, preferably a polymer or copolymer of acrylic acidor of maleic anhydride, preferably having a molecular weight of lessthan about 50,000. These thinning rheology modifiers are used for thesame purposes as the sulfoalkylated tannins discussed above, but theseagents work at higher solids content and at higher temperatures than thetannis. However, the tannins are less expensive. By using both, in thepreferred embodiment, cost savings can be obtained. An acceptable maleicanhydride copolymer may be obtained from Ciba Specialty Chemicals Corp.of Suffolk, Va.

In a preferred embodiment, the polyacrylate copolymer thinning rheologymodifier is provided in the drilling mud in concentrations between about0.71 grams per liter and about 5.7 grams per liter and more preferablyin concentrations of between about 1.4 and about 4.3 grams per liter. Asdiscussed in more detail below, the preferred embodiment of theinvention is a dry drilling mud additive, which is mixed into water tomake the drilling mud. To achieve the desired concentration, betweenabout 0.25 and about 2.0 pounds of polyacrylate copolymer rheologymodifier and preferably between about 0.5 and about 1.5 pounds ofpolyacrylate copolymer rheology modifier should be added per barrel (42gallons) of water.

In another preferred embodiment, a maleic anhydride copolymer is used asthe thinning rheology modifier. In this embodiment, the maleic anhydridecopolymer is provided in the drilling mud in concentrations of betweenabout 0.71 and about 5.7 grams per liter and more preferably betweenabout 1.4 and about 4.3 grams per liter. As discussed in more detailbelow, the preferred embodiment of the invention is a dry drilling mudadditive, which is mixed into water to make the drilling mud. To achievethe desired concentration, between about 0.25 and about 2.0 pounds ofmaleic anhydride copolymer rheology modifier and preferably betweenabout 0.25 and about 1.5 pounds of maleic anhydride copolymer rheologymodifier should be added per barrel (42 gallons) of water. An acceptablemaleic anhydride copolymer may be obtained from SKW Chemicals Corp. ofMarietta, Ga.

Micronized fibers, preferably finely ground plant materials or partsthereof, are also included in the preferred embodiment. Many differenttypes of materials can be used to provide the micronized fibersincluding natural and synthetic organic fibers, glass fibers, carbonfibers, inorganic fibers, rock wool fibers, metal fibers and mixturesthereof. The fibers can be of a variety of shapes ranging from simpleround or ovals to fibers having complex trilobed, figure eight, starshaped, or rectangular cross-sections. Curved, crimped, spiral shapedand other three dimensional fiber geometries may be used as well.Similarly, fibers with one or more hooked ends may be used.

The fibers sense to reduce the friction in the mud and to enhance theflow dynamics of the mud. It is believed that when the drilling mud ispumped along a tubular structure, such as the space between the wellbore wall and the drill string, the solids in the mud will align alongthe center of the structure, destabilizing fluid flow and increasingfriction. However, sufficient fibrous materials in the mud are believedto disperse the mud solids across the mud column. In any event, thepresence of fibrous material in the mud effects a reduction in pressurein the mud.

The fibrous materials also slow the settling rate of the mud solids,thereby permitting the use of lesser amounts of gelling rheologymodifiers. A reduced settling rate or higher gel strength will inhibitthe formation of cutting beds—collections of cuttings and other mudsolids at a point in the well bore. In turn, this will make it lesslikely that the bit or drill stem will become stuck. Also, the fibrousmaterials will help the mud stream flow as a plug, which will reduceerosion of the well bore.

The fibrous materials also help form the mud filter cake. They areparticularly suited to filling larger openings in fractured or otherwisehighly permeable formations. This helps to reduce mud loss and tominimize the chance of differential sticking in depleted sands.

In the preferred embodiment, the micronized fibers are provided in thedrilling mud in concentrations between about 2.9 grams per liter andabout 14.3 grams per liter and more preferably in concentrations ofbetween about 5.7 and about 11.4 grams per liter. As discussed in moredetail below, the preferred embodiment of the invention is a drydrilling mud additive, which is mixed into water to make the drillingmud. To achieve the desired concentration, between about 1.0 and about5.0 pounds of the micronized fibers and preferably between about 2.0 andabout 4.0 pounds of the micronized fibers should be added per barrel (42gallons) of water.

Another preferred component of the drilling mud is calcium carbonate,preferably having a particle size between about 1 and about 100 micronsand more preferably between about 5 and about 74 microns. Calciumcarbonate is particularly useful for blocking off fractured formationsand depleted sands, highly permeable formations whose pressure istypically lower than the hydrostatic pressure of the mud column. Thisprevents mud loss and the related problem of differential sticking.Additionally, calcium carbonate helps keep the dry mixture flowable.

In the preferred embodiment, calcium carbonate is provided in thedrilling mud in concentrations between about 5.7 grams per liter andabout 71.4 grams per liter and more preferably in concentrations ofbetween about 5.7 and about 28.6 grams per liter. As discussed in moredetail below, the preferred embodiment of the invention is a drydrilling mud additive, which is mixed into water to make the drillingmud. To achieve the desired concentration, between about 2.0 and about25.0 pounds of calcium carbonate and preferably between about 2.0 andabout 10.0 pounds of calcium carbonate should be added per barrel (42gallons) of water.

The drilling mud should preferably have a pH of about 7.0 to about 9.5.A neutral to moderately basic pH is desirable to minimize claydispersion, mud solids build up, and permeability damage to productivezones. A moderately basic mud pH will also to help the hydrationbuffers, and particularly humic acid, become water soluble. In high pHconditions, the clay particles may become more readily hydrated andbecome dispersed. When this occurs in the formation surrounding the wellbore, particularly low pressure sands containing clay particles, thedispersed clay may slow or prevent the flow of petroleum from theformation to the well bore, inhibiting production. When the clayparticles become hydrated and dispersed in the mud stream they maybecome too small to be removed, which will increase the solids contentof the mud and may result in the viscosity and yield point becomingexcessively high.

The desired pH may be achieved by adding sufficient quantities of anystandard base such as NaOH to the mixture. However, the inventor prefersto use bases such as KOH, Ca(OH)₂ or K₂CO₃. In the preferred embodiment,anhydrous potassium carbonate, K₂CO₃, is provided in the drilling mud inconcentrations between about 0.71 grams per liter and about 5.7 gramsper liter and more preferably in concentrations between about 2.9 andabout 4.3 grams per liter. Additionally, Ca(OH)₂ is provided in thedrilling mud in concentrations between about 0.71 and about 5.7 gramsper liter and more preferably in concentrations between about 0.71 andabout 2.9 grams per liter. As discussed in more detail below, thepreferred embodiment of the invention is a dry drilling mud additive,which is mixed into water to make the drilling mud. To achieve thedesired concentration, between about 0.25 and about 2.0 pounds of theK₂CO₃ and preferably between about 1.0 and about 1.5 pounds of the K₂CO₃should be added per barrel (42 gallons) of water. Likewise, betweenabout 0.25 and about 2.0 pounds of Ca(OH)₂ and preferably between about0.25 and about 1.0 pound of Ca(OH)₂ should be added per barrel (42gallons) of water. In one embodiment, the anhydrous potassium carbonatemay be omitted.

Although it is often desired to have a drilling mud that is neutral toslightly basic, many circumstances, such as mud contamination with CO₂gases or salt water, require a higher pH. The mud system of the presentinvention can be operated at such elevated pH levels if desired.

In addition to serving as a pH modifier, the Ca(OH)₂ is useful for itscalcium. The calcium in the mud will combine with carbonate gases thatescape from the formation into the mud stream to form calcium carbonate.The calcium carbonate will precipitate and can then be removed from themud.

Where increased carrying capacity of the drilling mud is desired inorder to suspend mud solids and cuttings, it may be desirable toincrease the gel strength of the drilling mud. This can be accomplishedby including an organic polymer such as xanthan gum, guar gum orhydroxyethyl cellulose in the mix or by adding it to the drilling fluidafter mixing. Another gelling rheology modifier which may be used toincrease the gel strength is bentonite (sodium montmorillonite). Asnoted above, the desired gel strength of the mud is preferably betweenabout three and about twelve pounds of force per hundred square feet,and more preferably between about four and about six pounds force (lbf)per hundred square feet, as measured when the mud has been at rest forten minutes. The related mud characteristic, yield point, shouldpreferably be from about five to about twenty pounds force (lbf) perhundred square feet, and preferably between about eight and about twelvepounds force (lbf) per hundred square feet.

Several factors affect the gel strength needed. Principally, however,the operator is balancing gel strength and yield point against theformation fracture gradient. The greater the volume of cuttings andcavings, the more important a high gel strength is in order to keepthose solids in suspension. Similarly, the closer the well bore angle isto horizontal, the more important gel strength is. In a nearly verticalwell bore, the solids typically have a long way to fall. Thus, a wellcan be shut down for an extended time before the solids would fall outof the mud stream. However, in a nearly horizontal well bore, thesuspended particles need only fall the width of the well bore to settleout of the mud stream. Therefore, as the well angle relative to verticalincreases, higher gel strengths are required.

Increased gel strength often means an increased yield point. This can bea problem because it means that greater pressure is required to get themud stream moving again. If the pressure on the mud exceeds the fracturegradient of the formation, the formation may rupture before the mudbegins moving, and mud may be lost to the formation. Thus, as notedabove, a drilling mud should preferably be thixotropic.

In a preferred embodiment, a gelling rheology agent in the form ofxanthan gum is provided in the drilling mud in concentrations betweenabout 0.29 grams per liter and about 2.9 grams per liter and morepreferably in concentrations between about 0.43 and about 1.4 grams perliter. As discussed in more detail below, the preferred embodiment ofthe invention is a dry drilling mud additive, which is mixed into waterto make the drilling mud. To achieve the desired concentration, betweenabout 0.1 and about 1.0 pounds of xanthan gum and preferably betweenabout 0.15 and about 0.5 pounds of xanthan gum should be added perbarrel (42 gallons) of water.

In another preferred embodiment, a gelling rheology agent in the form ofsodium montmorillonite (bentonite) is also included. Sodiummontmorillonite may be used in lieu of or in addition to xanthan gum.Sodium montmorillonite is provided in the drilling mud in concentrationsbetween about 5.7 grams per liter and about 71.3 grams per liter andmore preferably in concentrations between about 14.3 and about 48.8grams per liter. As discussed in more detail below, the preferredembodiment of the invention is a dry drilling mud additive, which ismixed into water to make the drilling mud. To achieve the desiredconcentration, between about 2.0 and about 25.0 pounds of sodiummontmorillonite and preferably between about 5.0 and about 15.0 poundsof sodium montmorillonite should be added per barrel (42 gallons) ofwater.

A better filter cake can be established by including a high quality clayin the mud. Sodium montmorillonite is the inventor's preferred clay. Itis sold as dry bentonite powder, available from Black Hills Bentonite,LLC of Mills, Wyo.

In some instances it may be preferable to add a gelling rheologymodifier after the mud has been mixed in order to adjust the mud's yieldpoint and gel strength in view of drilling conditions. Similarly, insome instances, no additional gelling rheology modifier will berequired.

Although the invention is described in terms of a single mud compositionand it could easily be mixed to provide one mix, the inventoranticipates making two separate dry mixes. The first will contain thehydration buffer (preferably humic acid), the shale stabilizers(preferably potassium acetate and/or PHPA) and filter cake componentssuch as cellulose polymer (preferably PAC) and sulfonated asphalt. Thesecond mix will contain a thinning rheology modifier (preferablysulfoalkylated tannin and/or maleic anhydride copolymer); micronizedfiber; calcium carbonate; a pH modifier (preferably Ca(OH)_(2,)potassium hydroxide, and/or anhydrous potassium carbonate); a gellingrheology modifier (preferably xanthan gum); and a high quality clay(preferably sodium montmorillonite). The first mix should preferablycontain the following components in concentrations of at least about theamounts listed below. The preferred concentrations of the second mixcomponents follows.

Component Percent, By Weight Pounds Per Barrel First Mix Leonardite (85%Humic Acid) 49.5 (42.1) 11 Potassium Acetate 13.5 3 PHPA 3.2 0.7 PAC 6.81.5 Sulfonated Asphalt 27.0 6 Second Mix Sulfoalkylated Tannin 16.0 1.25Maleic Anhydride Copolymer 6.4 0.5 Micronized Fiber 46.2 3.6 CalciumCarbonate 25.6 2 Calcium Hydroxide 5.8 0.45

In a preferred embodiment, the second mix component will comprise atleast about 5.0 percent by weight of a first rheology agent selectedfrom the group consisting of sulfoalkylated tannins, lignosulfonate,copolymers of acrylic acid and polyacrylic acid, polystyrene maleicanhydride copolymer, 2-acrylomido-2-methylpropane sulfonic acid polymer,and combinations thereof.

In mixing the preferred embodiment of the dry mixes, the componentsshould preferably be mixed in the order listed in the foreground charts.The components should be added to a dry ribbon-type blender in theratios outlined and mixed until homogenous. The two separate powdermixes should preferably be stored in plastic lined, moisture proof bagsor bulk tanks. In the preferred embodiment, rather than storing themixes in powder form, the mixes may be compressed into pellets having avolume from about 0.25 cubic centimeters to about 10 cubic centimeters.This will increase the bulk density of the powder by a factor of about25 to 75 percent, thereby substantially facilitating storage andshipping.

The first mix may be used independently as a shale stabilizer and mudfiltrate reducer by adding it directly to fresh water, salt water, or anexisting drilling fluid through a chemical hopper at a concentrationbetween about 10 and about 30 pounds, and preferably about 25 pounds,per barrel (42 gallons). The second mix could be used as a sealant inexisting mud systems. The concentrations needed of the second mix whenit is used as a separate sealant will vary depending upon the needs ofthe existing system.

Where a total mud system is required, the two mixes should be combined.A drilling mud may be formed by mixing between about 20 pounds and about40 pounds, and preferably about 30 pounds, of the combined blend perbarrel (42 gallons) of fresh or salt water, while circulating with acentrifugal pump and stirring with a paddle agitator, at ambienttemperature until a homogenous mixture is obtained, typically between 30and 60 minutes. Sufficient base, preferably KOH, is added to the waterprior to mixing to raise the pH to about 12.8. The dry mix componentswill lower the pH to the desired levels.

When the drilling mix is added to an existing mud, a presolubilizingstep is preferred. Approximately one hundred fifty barrels of water aremixed with sufficient KOH to raise the pH to about 13.5. Roughly 60pounds of combined mix is added per barrel (˜9000 pounds), and thenmixed as described above. The addition of the dry mix ingredients lowersthe pH to the desired level. When mixing is complete, the resultantfluid is added to the existing mud.

The drilling mud formed pursuant to the foregoing instructions will bean unweighted drilling mud, or at least not an intentionally weightedmud. Muds are weighted to hold back the formation pressure and therebyprevent the petroleum from entering the well bore. Muds made from thepresent additives can be weighted by adding minerals such as barite,calcium carbonate or hematite, if desired. Thinning or gelling rheologyagents and/or pH modifiers may be added at this stage to adjust the mudproperties, if needed.

Other uses and embodiments of the invention will occur to those skilledin the art from the foregoing disclosure, and are intended to beincluded within the scope and spirit of the claims which follow.

I claim:
 1. A substantially water soluble additive mixture for additionto a drilling fluid, said additive mixture comprising: a shalestabilizer selected from the group consisting of an alkali metalacetate, partially hydrolyzed polyacrylate-polyacrylamide copolymer, andcombinations thereof; and a hydration buffer comprising humic acid, saidhydration buffer provided in sufficient amount to inhibit substantialabsorption of water from the atmosphere whereby said mixture will remainsubstantially dry and flowable.
 2. A substantially water solubleadditive mixture for addition to a drilling fluid according to claim 1wherein said alkali metal acetate comprises potassium acetate.
 3. Asubstantially water soluble additive mixture for addition to a drillingfluid according to claim 2 wherein said potassium acetate is provided inquantities sufficient to yield concentrations of between about 2.9 andabout 14.3 grams per liter of said drilling fluid.
 4. A substantiallywater soluble additive mixture for addition to a drilling fluidaccording to claim 1 wherein said partially hydrolyzedpolyacrylate-polyacrylamide copolymer has a molecular weight betweenabout 1 million and about 8 million.
 5. A substantially water solubleadditive mixture for addition to a drilling fluid according to claim 4wherein said partially hydrolyzed polyacrylate-polyacrylamide copolymeris provided in quantities sufficient to yield concentrations betweenabout 0.71 and about 5.7 grams per liter of said drilling fluid.
 6. Asubstantially water soluble additive mixture for addition to a drillingfluid according to claim 1 wherein said humic acid is provided inquantities sufficient to yield concentrations of between about 4.9 andabout 36.4 grams per liter of said drilling fluid.
 7. A substantiallywater soluble additive mixture for addition to a drilling fluidaccording to claim 1 wherein said humic acid is provided in the form ofleonardite.
 8. A substantially water soluble additive mixture foraddition to a drilling fluid according to claim 7 wherein saidleonardite is provided in quantities sufficient to yield concentrationsbetween about 5.7 and about 42.9 grams per liter of said drilling fluid.9. A substantially water soluble additive mixture for addition to adrilling fluid according to claim 1 further comprising a cellulosepolymer.
 10. A substantially water soluble additive mixture for additionto a drilling fluid according to claim 9 wherein said cellulose polymeris selected from the group consisting of polyanionic cellulose polymer,carboxymethylcellulose, and combinations thereof.
 11. A substantiallywater soluble additive mixture for addition to a drilling fluidaccording to claim 9 wherein said cellulose polymer is provided inquantities sufficient to yield concentrations between about 0.71 and11.4 grams per liter of said drilling fluid.
 12. A substantially watersoluble additive mixture for addition to a drilling fluid according toclaim 1 further comprising a sealant selected from the group consistingof asphalts, gilsonite, carbon black, graphite, and combinationsthereof.
 13. A substantially water soluble additive mixture for additionto a drilling fluid according to claim 12 wherein said sealant comprisesan asphalt.
 14. A substantially water soluble additive mixture foraddition to a drilling fluid according to claim 13 wherein said asphaltfurther comprises a sulfonated asphalt.
 15. A substantially watersoluble additive mixture for addition to a drilling fluid according toclaim 13 wherein said asphalt is provided in quantities sufficient toyield concentrations between about 5.71 and about 28.6 grams per literof said drilling fluid.
 16. A substantially water soluble drilling fluidmix comprising: a first mix component comprising at least about 42.1percent by weight humic acid; at least about 13.5 percent by weightalkali metal acetate; at least about 3.2 percent by weight partiallyhydrolyzed polyacrylate-polyacrylamide copolymer; at least about 6.8percent by weight cellulose polymer; and at least about 27.0 percent byweight of a sealant selected from the group consisting of asphalts,gilsonite, carbon black, graphite, and combinations thereof; and asecond mix component comprising at least about 5.0 percent by weight ofa first rheology agent selected from the group consisting ofsulfoalkylated tannins, lignosulfonate, copolymers of acrylic acid andpolyacrylic acid, polystyrene maleic anhydride copolymer,2-acrylomido-2-methylpropane sulfonic acid polymer, and combinationsthereof.
 17. A substantially water soluble drilling fluid mix accordingto claim 16 wherein said second mix component further comprises at leastabout 46.2 percent by weight of a micronized fiber.
 18. A substantiallywater soluble drilling fluid mix according to claims 17 wherein saidmicronized fiber is selected from a group consisting of natural organicfibers, synthetic organic fibers, glass fibers, carbon fibers, inorganicfibers, rock wool fibers, metal fibers and mixtures thereof.
 19. Asubstantially water soluble drilling fluid mix according to claim 16wherein said second mix component further comprises at least about 25.6percent by weight of calcium carbonate.
 20. A substantially watersoluble drilling fluid mix according to claim 16 wherein said second mixcomponent comprises a second rheology agent in sufficient quantities toestablish a yield point of at least about 5 pounds force per 100 squarefeet in a solution formed from mixing said first and second mixtureswith water to form a drilling fluid.
 21. A substantially water solubledrilling fluid mix according to claim 20 wherein said second rheologyagent comprises an organic polymer selected from the group consisting ofxanthan gum, guar gum, hydroxyethyl cellulose, and combinations thereof.22. A substantially water soluble drilling fluid mix according to claim16 wherein said second mix component further comprises a pH modifyingagent in sufficient quantities to maintain a pH of at least about 7 in asolution formed from mixing said first and second mix components withwater to form a drilling fluid.
 23. A substantially water solubledrilling fluid mix according to claim 22 wherein said pH modifying agentis selected from the group consisting of calcium hydroxide, potassiumhydroxide, sodium carbonate, potassium carbonate, and combinationsthereof.
 24. A substantially water soluble drilling fluid mix accordingto claim 16 wherein said alkali metal acetate comprises potassiumacetate.
 25. A substantially water soluble drilling fluid mix accordingto claim 16 wherein said cellulose polymer is selected from the groupconsisting of polyanionic cellulose polymer, carboxymethylcellulose, andcombinations thereof.
 26. A substantially water soluble drilling fluidmix according to claim 16 wherein said sealant comprises an asphalt. 27.A substantially water soluble drilling fluid mix according to claim 26wherein said asphalt comprises a sulfonated asphalt.
 28. A substantiallywater soluble drilling fluid mix according to claim 16 furthercomprising clay.
 29. A substantially soluble drilling fluid mixaccording to claim 28 wherein said clay comprises sodiummontmorillonite.
 30. A substantially soluble drilling fluid mixaccording to claim 16 wherein said first mix component is dry andflowable.
 31. A substantially soluble drilling fluid mix according toclaim 30 wherein said second mix component is dry and flowable.
 32. Asubstantially soluble drilling fluid mix according to claim 16 whereinsaid first mix component is pelletized.
 33. A substantially solubledrilling fluid mix according to claim 32 wherein said second mixcomponent is pelletized.
 34. A method of stabilizing shale in anexisting borehole having a drilling fluid comprising mixing an additiveinto said drilling fluid, said additive comprising: between about 0.71and about 5.71 grams of a partially hydrolyzedpolyacrylate-polyacrylamide copolymer per liter of said drilling fluid;between about 2.9 and about 14.3 grams of an alkali metal acetate perliter of said drilling fluid; between about 4.8 and about 36.5 grams ofhumic acid per liter of said drilling fluid; between about 0.71 andabout 11.4 grams of cellulose polymer per liter of said drilling fluid;between about 5.7 and about 28.6 grams of a sealant selected from thegroup consisting of asphalts, gilsonite, carbon black, graphite, andcombinations thereof per liter of said drilling fluid; and circulatingsaid drilling fluid with said additives through said borehole.
 35. Amethod of stabilizing shale in an existing borehole having a drillingfluid according to claim 34 wherein said additive further comprisesbetween about 1.4 and about 14.3 grams per liter of a rheology agentselected from the group consisting of sulfoalkylated tannins,lignosulfonate, copolymers of acrylic acid and polyacrylic acid,polystyrene maleic anhydride copolymer, 2-acrylomido-2-methylpropanesulfonic acid polymer, and combinations thereof.
 36. A substantiallywater soluble additive mixture for addition to a drilling fluid, saidadditive mixture comprising: a shale stabilizer selected from the groupconsisting of an alkali metal acetate, partially hydrolyzedpolyacrylate-polyacrylamide copolymer, and combinations thereof; asufficient amount of hydration buffer to inhibit substantial absorptionof water from the atmosphere whereby said mixture will remainsubstantially dry and flowable; and a sealant selected from the groupconsisting of asphalts, gilsonite, carbon black, graphite, andcombinations thereof.
 37. A substantially water soluble additive mixturefor addition to a drilling fluid according to claim 36 wherein saidsealant comprises an asphalt.
 38. A substantially water soluble additivemixture for addition to a drilling fluid according to claim 37 whereinsaid asphalt further comprises a sulfonated asphalt.
 39. A substantiallywater soluble additive mixture for addition to a drilling fluidaccording to claim 37 wherein said asphalt is provided in quantitiessufficient to yield concentrations between about 5.71 and about 28.6grams per liter of said drilling fluid.
 40. A substantially watersoluble additive mixture for addition to a drilling fluid according toclaim 36 wherein said alkali metal acetate comprises potassium acetate.41. A substantially water soluble additive mixture for addition to adrilling fluid according to claim 40 wherein said potassium acetate isprovided in quantities sufficient to yield concentrations of betweenabout 2.9 and about 14.3 grams per liter of said drilling fluid.
 42. Asubstantially water soluble additive mixture for addition to a drillingfluid according to claim 36 wherein said partially hydrolyzedpolyacrylate-polyacrylamide copolymer has a molecular weight betweenabout 1 million and about 8 million.
 43. A substantially water solubleadditive mixture for addition to a drilling fluid according to claim 42wherein said partially hydrolyzed polyacrylate-polyacrylamide copolymeris provided in quantities sufficient to yield concentrations betweenabout 0.71 and about 5.7 grams per liter of said drilling fluid.
 44. Asubstantially water soluble additive mixture for addition to a drillingfluid according to claim 36 further comprising a cellulose polymer. 45.A substantially water soluble additive mixture for addition to adrilling fluid according to claim 44 wherein said cellulose polymer isselected from the group consisting of polyanionic cellulose polymer,carboxymethylcellulose, and combinations thereof.
 46. A substantiallywater soluble additive mixture for addition to a drilling fluidaccording to claim 44 wherein said cellulose polymer is provided inquantities sufficient to yield concentrations between about 0.71 and11.4 grams per liter of said drilling fluid.